In the context of oil extraction, many oil reservoirs are fractured and much oil remains trapped therein after classical enhanced oil recovery processes, such as water flooding, gas injection or in-situ combustion, have finished. The high remaining oil saturation could be due to a poor sweep in these reservoirs by these conventional primary extraction approaches. Polymer flooding processes using natural polymers, such as xanthan and starch, synthetic polymers, such as polyacrylamide (PAM) and partially hydrolyzed polyacrylamide (HPAM), can significantly increase the oil recovery percentage, as compared to the aforesaid conventional water flooding process, in a significant number of these unspent reservoirs. A treatment by polymer flooding has various benefits, including increasing the viscosity of injected water, which increases sweep efficiency due to the improved mobility ratio, and reducing the total volume of water required to reach the residual oil saturation.
As mentioned hereinabove, PAM and HPAM are the most widely used polymers to control the mobility ratio of water to oil in the so-called secondary and tertiary oil recovery processes and methodologies. As mentioned, these polymers increase the water viscosity, hindering water fingering phenomena and pushing the oil forward or to the front for retrieval, as a result from the extremely high molecular weight of the polymers, and the repulsion between the negative charges along the polymer chain, is based on maximum chain extension. However, there are many limitations with traditional polymer flooding technologies, such as thermal, mechanical, salinity, shear and biological degradations of polymer chains during the flooding process.
The aforementioned chain extension approach leads to one of the greatest disadvantages of using PAM and HPAM in oil reservoirs. For example, when polyvalent salts are used in oilfield brine solutions, negative charges are extended from each other along the polymer chain by interaction with cations in the solution. The polymer chains, no longer extend fully, cause the solution to have decreased viscosity due to the ion-dipole interaction between the salt cations and the oxygen atoms in polyacrylamide molecules. The strong ion-dipole interaction between the divalent cations, Ca2+ and Mg2+ and the amide group because of higher charge densities than Na+, weakens the bond strengths of NaH and C═O bonds. This phenomena leads to the chemical degradation of polymer molecules and decreases the polymer solution viscosity.
In addition, shearing and heating in wellbores and reservoirs often decrease the polymer viscosity. Polymer solutions, as any non-Newtonian fluid, conform to the power law, including viscosity, shear rate, consistency index, and flow behavior index. The polymer solution viscosity is thus easily calculated under any shear rate based on the determined consistency and flow behavior indexes as with any fluid. As is understood in the art, the consistency index increases with increasing polymer concentration, but decreases with increasing temperature. On the other hand, the flow behavior index decreases with increasing polymer concentration, and slightly increases at high temperature. Therefore, it should be understood that a higher HPAM concentration leads to higher viscosities, and polymer viscosity is reduced at a higher shear rate and temperature.
Mechanical degradation of acrylamide-based polymers, as a result of flow through pumps, chokes and valves, as well as action at the sand face, have been recently reported as a disadvantage in oil reservoir applications, where the rheology properties and mechanical degradation were measured by mobility reduction, and the loss in viscosity of the solution effluent, respectively. In the particular range of shear rates, the polymer solution generally shows thickening and thinning behaviors with shear rate increasing. Thus, the thickening behavior is found to be due to the coil-stretch transition at the entry point, and the flow in the bulk of the capillaries is found purely thinning in the whole shear rate ranges. Regarding the effect of shear in the bulk of the capillaries, the degradation starts to increase above a critical shear rate, for example, 15000 s−1, and the entry point degradation sharply increases polymer degradation at high shear rates, for example, 850,000 s−1.
It should, therefore, be understood that these results show at least three points: 1) that high shear equipment, such as pumps, chokes and valves, can have a detrimental influence on the mechanical strength of the polymer chains, and hence should be utilized with caution, 2) more mechanically-stable polymers can be utilized, and 3) the polymer entanglement at the sand face, and the flow of polymer through perforations and throats, can further degrade the polymer, leading to mobility reduction.
Water soluble polymers, such as polyacrylamide, partially hydrolyzed polyacrylamide, and thermoviscosifying polymer with polyacrylamide main chains, have been widely used in enhanced oil recovery (EOR) approaches to increase the viscosity of injected water, which increases sweep efficiency due to the aforesaid improved mobility ratio. The main problem of using these materials is related to the increase of the water viscosity in undesired directions, such as before reaching the remaining secondary and tertiary oil areas. Additionally, mechanical, thermal and bacterial damages, as well as surface absorption, of these polymers indicate additional limitations of these traditional polymer flooding techniques.
Much effort has been expended to overcome the above-mentioned limitations in polymer flooding with polyacrylamide solutions, such as the copolymerization of acrylamide, with more resistant monomers, such as thermoviscosifying polymers (TVPs). TVP viscosity increases with increasing temperature and salinity due to the association temperature (Tass), which may overcome the aforementioned disadvantages of most water soluble polymers against high temperature and salinity conditions. However, heavy biological and mechanical environments can dissociate these structures because of the above mentioned effects.
Recently, smart coating has been considered as a more sophisticated approach for protection and controlled release of precious materials in many applications, particularly with the increase in manufacturing nano-sized particles and structures. For example, in analyzing a drug delivery study as a smart system, where transporting a pharmaceutical compound through the body as needed to safely achieve its desired therapeutic effect at a particular loci, this technology model has been adapted for use in reservoirs, and is one of the advanced technology paradigms adopted in this case. In these advanced systems, a considered pharmaceutical compound, e.g., as a hydrophobic material (core material), is capsulated or coated (chemically graft) with one or two hydrophilic polymers via solution, radiation induced, suspension, and emulsion polymerizations, which have responses to a determined or predetermined stimuli, encapsulating the core material in nanolayers.
It should be understood that encapsulation (e.g., the physical coating of a particle with another material) of hydrophilic polymers by hydrophobic polymer nanolayers is useful technique to protect the active materials, a general description for which is set forth in a related case, U.S. patent application Ser. No. 13/730,938, with a common inventor to the instant case.
Accordingly, a polymeric shell acts as a protective layer for a water soluble polymer, preventing rapid degradation and mechanical shear stresses, both in surface facilities and near the wellbore. Therefore, when the core-shell nanostructures reach the oil-water interface, the hydrophobic polymeric outer shell or nanolayers dissolves in the oil phase, and the hydrophilic core polymer, after passage and penetration through the hydrophobic wall, is able to propagate in the whole water phase, leading to beneficial increases in water viscosity. However, in the aforesaid encapsulation technique, although the active materials are protected and the less hydrophilic outer polymer coating or nanolayers are considerably consumed during an enhanced oil recovery (EOR) process, the polymer propagation in the water phase, after the hydrophobic nanolayer penetration in the oil phase, can nonetheless fail to thicken at the frontier with high viscosity water because of nanoparticle dispersion in the whole water phase.
Thus, there is a present need for an improved technique and composition to overcome this obstacle. Here, the external hydrophobic polymer block of the block copolymer shell penetrates in the oil phase and the internal hydrophilic polymer block with the core part remains in the water phase. Thus, in operation, there is a need for an improved composition and structure that results in the thickening or increasing of the viscosity of the downstream water phase, which pushes the oil to the production wells.
On the other hand, there is also a need for an improved EOR process involving nanostructures of a hydrophilic core-surfmer shell, which follows the viscosity increase and interfacial tension reduction mechanisms because of the release of high molecular weight hydrophilic polymers and surfactants in the oil-water interface. Consequently, the this technique not only acts as a protective layer for water soluble polymer from rapid degradations, but also targets delivery in another approach for an enhanced oil recovery process.
There is, therefore, a present need for such improved materials, compositions and manufactures to facilitate in extraction of oil, such as in secondary and tertiary extraction of oil and other materials.
These and many other objects are met in various embodiments of the present invention, offering significant advantages over the known prior art and consequent benefits in the extraction techniques.